Subterranean treatment fluids are commonly used in stimulation, sand control, and completion operations. As used herein, the term “treatment,” or “treating,” refers to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The term “treatment,” or “treating,” does not imply any particular action by the fluid.
An example of a subterranean treatment that often uses an aqueous treatment fluid is hydraulic fracturing. In a hydraulic fracturing treatment, a viscous fracturing fluid is introduced into the formation at a high enough rate to exert sufficient pressure on the formation to create and/or extend fractures therein. The viscous fracturing fluid suspends proppant particles that are to be placed in the fractures to prevent the fractures from fully closing when hydraulic pressure is released, thereby forming conductive channels within the formation through which hydrocarbons can flow toward the well bore for production. In certain circumstances, variations in the subterranean formation will cause the fracturing fluid to create and/or extend fractures non-uniformly. Typically, one or more dominant fractures may extend more rapidly than non-dominant fractures. These dominant fractures utilize significantly more fracturing fluid than non-dominant fractures, thereby reducing pressure on non-dominant fractures and slowing or stopping their extension. Dominant fractures can be identified using fiber optics to measure fluid flow rates to each fracture and/or using micro-seismic sensors to detect the growth rate and direction of the fractures. Operators have addressed the unbalanced distribution of fracture fluid by introducing a certain quantity of diverters into the fracturing fluid when dominant fractures are identified. The diverters travel to the dominant fractures and restrict the flow of fracturing fluid to the dominant fractures or plug the dominant fractures. In some applications, these diverters are composed of degradable materials, including water-hydrolysable materials such as polylactic acid, which degrade over time and restore permeability to plugged or restricted fractures.
Typically, operators have relied on a desired fluid pressure per fracture as a rule of thumb to determine when to introduce diverters to the fracturing fluid without regard for specific features of the subterranean formation. Introduction of an insufficient quantity of diverters to properly restrict dominant fractures may delay redistribution of fracturing fluid flow and slow treatment of the formation. Introduction of an excess quantity of diverters may plug both dominant and non-dominant fractures causing unnecessary pressure build up.
Thus it is desirable to consider real-time information about the features of the subterranean formation and/or historical data for similar subterranean formations to determine both when to introduce diverters to the fracturing fluid and the quantity of diverters to introduce to properly redistribute fracturing fluid between the subterranean fractures.
While embodiments of this disclosure have been depicted and described and are defined by reference to exemplary embodiments of the disclosure, such references do not imply a limitation on the disclosure, and no such limitation is to be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those skilled in the pertinent art and having the benefit of this disclosure. The depicted and described embodiments of this disclosure are examples only, and not exhaustive of the scope of the disclosure.